Systems and methods for improving reservoir fluid recovery from fractured subterranean formations

ABSTRACT

Systems and methods for improving reservoir fluid recovery from fractured subterranean formations. The methods may include injecting a pressurizing fluid into an injection fracture that extends within a subterranean formation and producing a produced fluid from a production fracture that extends within the subterranean formation. The production fracture is spaced apart from the injection fracture and is in indirect fluid communication with the injection fracture via a portion of the subterranean formation that extends therebetween and the pressurizing fluid injection provides a motive force for the production of the produced fluid. The methods further include injecting a foaming agent into the production fracture to limit production of the pressurizing fluid from the production fracture. The systems may include hydrocarbon production systems that may be utilized to perform the methods and/or that may be created while performing the methods.

CROSS-REFERENCE TO RELATED APPLICATION

This application claims the priority benefit of U.S. Provisional PatentApplication 61/845,862 filed Jul. 12, 2013 entitled SYSTEMS AND METHODSFOR IMPROVING RESERVOIR FLUID RECOVERY FROM FRACTURED SUBTERRANEANFORMATIONS, the entirety of which is incorporated by reference herein.

FIELD

The present disclosure is directed generally to systems and methods forimproving reservoir fluid recovery from fractured subterraneanformations, and more particularly to systems and methods that includeinjection of a foaming agent into a production fracture to enhanceproduction of the reservoir fluid from the subterranean formation and/orto limit production of a pressurizing fluid from the subterraneanformation.

BACKGROUND

Production of reservoir fluid (or hydrocarbons) from low permeabilityreservoirs (or hydrocarbon reservoirs), such as reservoirs with fluidpermeabilities of less than 10 millidarcy (md), presents uniquechallenges associated with generation of acceptable flow rates of thereservoir fluid within the reservoir and/or economical production ratesof the reservoir fluid from the reservoir. However, because of the largenumber of low permeability reservoirs that exist, their overall size,and the volume of hydrocarbons that are contained therein, the potentialrewards associated with production from these low permeabilityreservoirs are substantial. Thus, the oil and gas industry is devotingsignificant resources to the development of economical productionmethodologies for low permeability reservoirs.

One such production methodology is hydraulic fracturing, which generatesfractures in the low permeability reservoir to increase the fluidpermeability of the reservoir. While hydraulic fracturing may permitproduction of some of the reservoir fluid that is present within lowpermeability reservoirs, the maximum achievable recovery typically isonly 15%.

One challenge associated with increasing the economic recovery ofreservoir fluid is generation of a driving force for fluid flow withinthe reservoir. Conventionally, reservoirs that have been hydraulicallyfractured rely upon volumetric expansion of the reservoir fluid and/orcompaction of the reservoir itself to provide the driving force forreservoir fluid production, and attempts to provide additional pressuresupport often have been unsuccessful.

For example, and in conventional (or high permeability) reservoirs,water may be injected to pressurize the reservoir and provide a drivingforce for production of reservoir fluid from the reservoir. However, inlow permeability reservoirs, water injection may be ineffective due tolow water permeability of the reservoir, plugging of a pore space withinthe reservoir, and/or injection pressure constraints. An alternative towater injection is gas injection. However, this approach also has beenlargely unsuccessful due to the relatively tight well spacing that isutilized in low permeability reservoirs and the existence of higherpermeability zones or streaks within the reservoir. These higherpermeability zones may serve as bypass pathways that permit the injectedgas to flow from an injection well to a production well withoutproviding a desired level of pressure support for production ofreservoir fluid from the reservoir. Thus, there exists a need forimproved systems and methods for improving reservoir fluid recovery fromfractured subterranean formations, including fractured low permeabilitysubterranean formations.

SUMMARY

Systems and methods for improving reservoir fluid recovery fromfractured subterranean formations are disclosed herein. The methods mayinclude injecting a pressurizing fluid into an injection fracture thatextends within a subterranean formation and producing a produced fluidfrom a production fracture that extends within the subterraneanformation. The production fracture is spaced apart from the injectionfracture and is in indirect fluid communication with the injectionfracture via a portion of the subterranean formation that extendstherebetween and the pressurizing fluid injection provides a motiveforce for the production of the produced fluid. The methods further mayinclude injecting a foaming agent into the production fracture to limitproduction of the pressurizing fluid from the production fracture.

The methods further may include ceasing the producing during theinjecting the foaming agent and resuming the producing subsequent to theinjecting the foaming agent. The injecting the pressurizing fluid andthe injecting the foaming agent may be performed at least partiallyconcurrently. Additionally or alternatively, the injecting thepressurizing fluid and the injecting the foaming agent may be performedsequentially. Further additionally, the injecting the foaming agent mayoccur prior to the injecting the pressurizing fluid.

A single wellbore may be utilized to provide both the pressurizing fluidand the foaming agent to the injection fracture and the productionfracture, respectively. Additionally or alternatively, separatewellbores may be utilized to provide the pressurizing fluid and thefoaming agent to the injection fracture and the production fracture,respectively.

Injecting the foaming agent may include injecting a substantiallycontinuous foaming agent stream. The injecting the foaming agent mayinclude injecting alternating volumes of a liquid foaming agent and agas. The injecting the foaming agent may include preferentiallydiverting the pressurizing fluid into an unproduced region of thesubterranean formation.

The methods further may include forming the injection fracture and/orthe production fracture. The forming may include restrictingintersection of the injection fracture and the production fracture. Themethods further may include repeating at least a portion of the methods.

The methods further may include detecting a variable associated withproduction of the pressurizing fluid from the production fracture andthe injecting the foaming agent is based, at least in part, on thedetecting. The methods further may include determining that thepressurizing fluid is being produced from the production fracture andthe injecting the foaming agent is based, at least in part, on thedetermining.

The systems include hydrocarbon production systems that may be utilizedto perform the methods and/or that may be created while performing themethods and include the injection fracture and the production fracture.The systems further may include a pressurizing fluid supply system thatis configured to inject the pressurizing fluid into the injectionfracture and a foaming agent supply system that is configured toselectively inject the foaming agent into the production fracture.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic representation of illustrative, non-exclusiveexamples of a hydrocarbon production system that may include and/orutilize the systems and methods according to the present disclosure.

FIG. 2 provides schematic cross-sectional views of illustrative,non-exclusive examples of a subterranean formation that includes aninjection fracture and a production fracture that may be utilized withthe systems and methods according to the present disclosure.

FIG. 3 is another schematic cross-sectional view of the subterraneanformation of FIG. 2 subsequent to production of a portion of thereservoir fluid from the subterranean formation.

FIG. 4 is another schematic cross-sectional view of the subterraneanformation of FIG. 3 subsequent to injection of a foaming agent into theproduction fracture.

FIG. 5 is another schematic cross-sectional view of the subterraneanformation of FIG. 4 during production of additional reservoir fluid fromthe subterranean formation.

FIG. 6 is a flowchart depicting methods according to the presentdisclosure.

DETAILED DESCRIPTION

FIGS. 1-5 provide illustrative, non-exclusive examples of hydrocarbonproduction systems 10 according to the present disclosure, componentsthereof, and/or process flows that may be utilized therewith. Elementsthat serve a similar, or at least substantially similar, purpose arelabeled with like numbers in each of FIGS. 1-5, and these elements maynot be discussed in detail herein with reference to each of FIGS. 1-5.Similarly, all elements may not be labeled in each of FIGS. 1-5, butreference numerals associated therewith may be utilized herein forconsistency. Elements, components, and/or features that are discussedherein with reference to one or more of FIGS. 1-5 may be included inand/or utilized with any of FIGS. 1-5 without departing from the scopeof the present disclosure.

In general, elements that are likely to be included are illustrated insolid lines, while elements that are optional are illustrated in dashedlines. However, elements that are shown in solid lines may not beessential, and an element shown in solid lines may be omitted withoutdeparting from the scope of the present disclosure.

FIG. 1 is a schematic representation of illustrative, non-exclusiveexamples of a hydrocarbon production system 10 that may include and/orutilize the systems and methods according to the present disclosure.Hydrocarbon production system 10 is configured to produce a reservoirfluid 22 from a subterranean formation 20 that is present within asubsurface region 14. As illustrated in FIG. 1, hydrocarbon productionsystem 10 includes an injection fracture 50 and a production fracture60, both of which extend within the subterranean formation (such as toincrease a fluid permeability of the subterranean formation). Theproduction fracture is spaced apart from the injection fracture and isin indirect fluid communication with the production fracture via aportion 24 of subterranean formation 20 that extends therebetween.

Hydrocarbon production system 10 further includes a pressurizing fluidsupply system 80 that is configured to inject a pressurizing fluid 82into injection fracture 50 (such as via a suitable wellbore 30). Thepressurizing fluid increases a pressure within subterranean formation 20proximal to, locally to, and/or in a vicinity of injection fracture 50.This increase in pressure provides a driving, or motive, force for flowof reservoir fluid 22 that may be present within portion 24 of thesubterranean formation into production fracture 60. The reservoir fluidthen may flow from the subterranean formation to a surface region 12(such as via a suitable wellbore 30) as a produced fluid 62.

Hydrocarbon production system 10 also includes a foaming agent supplysystem 90 that is configured to selectively inject a foaming agent 92into production fracture 60. As discussed in more detail with referenceto FIGS. 2-5, foaming agent 92 may form, generate, produce, and/orbecome a flow restriction within subterranean formation 20, therebylimiting flow of pressurizing fluid 82 from injection fracture 50 toproduction fracture 60 and/or limiting production of pressurizing fluid82 from the production fracture.

FIGS. 2-5 are schematic cross-sectional views of illustrative,non-exclusive examples of a subterranean formation 20 that includes aninjection fracture 50 and a production fracture 60 that may be utilizedwith the systems and methods according to the present disclosure andthat may include and/or be subterranean formation 20, injection fracture50, and/or production fracture 60 of FIG. 1. In FIG. 2, pressurizingfluid 82 is provided to injection fracture 50. As illustrated indash-dot lines in FIG. 2, pressurizing fluid 82 may flow into portion 24of subterranean formation 20 that is located between injection fracture50 and production fracture 60. Pressurizing fluid 82 may pressurize thesubterranean formation in a region that is proximal to the injectionfracture. This may provide a driving force for flow of reservoir fluid22 from portion 24 and into production fracture 60, as illustrated. Thereservoir fluid then may be produced from production fracture 60 asproduced fluid 62.

In FIG. 2, produced fluid 62 is illustrated as exiting productionfracture 60 from a portion of the production fracture that is proximalto a portion of injection fracture 50 that receives pressurizing fluid82 and/or from a portion of the production fracture that is distal fromthe portion of the injection fracture that receives the pressurizingfluid. The conduit that provides pressurizing fluid 82 to the injectionfracture and the conduit that receives produced fluid 62 from theproduction fracture may be proximal to one another (or located in thesame wellbore) and/or may be distal from one another (or located indifferent wellbores).

FIG. 2 also illustrates in dashed lines that pressurizing fluid 82 mayflow through portion 24 of subterranean formation 20 and enterproduction fracture 60. This pressurizing fluid may combine withreservoir fluid 22 to form a portion of produced fluid 62 and beproduced from the subterranean formation, as discussed in more detailherein with reference to FIG. 3. However, the presence of pressurizingfluid 82 (or a significant amount of pressurizing fluid 82) withinproduced fluid 62 may be undesirable and/or may decrease an overallefficiency of hydrocarbon production system 10.

FIG. 3 illustrates that pressurizing fluid 82 may flow through certainregions of portion 24 of subterranean formation 20, while bypassing, orchanneling around, other regions of portion 24. Thus, and subsequent toproviding pressurizing fluid 82 to subterranean formation 20 for aperiod of time, portion 24 may include produced regions 72, in which asubstantial portion of reservoir fluid 22 has been removed and/or swept,and unproduced regions 76, wherein a substantial portion of reservoirfluid 22 remains. The flow through produced regions 72 may bedetrimental to maximizing production of reservoir fluid 22 fromsubterranean formation 20 and/or may decrease an overall efficiency ofproduction of the reservoir fluid from the subterranean formation.

As an illustrative, non-exclusive example, and since pressurizing fluid82 simply may flow from injection fracture 50 to production fracture 60via produced regions 72, reservoir fluid that is present withinunproduced regions 76 may not be removed from the subterraneanformation. As another illustrative, non-exclusive example, flow ofpressurizing fluid 82 through produced regions 72 may increase aproportion of the pressurizing fluid within produced fluid 62, therebydecreasing an overall efficiency of production of reservoir fluid 22from subterranean formation 20.

Such a structure may be present when subterranean formation 20 is aheterogeneous subterranean formation 20 that includes regions and/orzones of varying fluid permeability. As an illustrative, non-exclusiveexample, produced regions 72 may represent regions of (relatively)higher fluid permeability, while unproduced regions 76 may representregions of (relatively) lower fluid permeability. With this in mind, thesystems and methods according to the present disclosure may be effectiveat improving reservoir fluid production from both heterogeneoussubterranean formations and homogeneous subterranean formations;however, the benefits of the systems and methods according to thepresent disclosure may increase for heterogeneous subterraneanformations.

Thus, and as illustrated in FIG. 4, the systems and methods includeinjection of a foaming agent 92 into production fracture 60. Foamingagent 92 may flow from production fracture 60 into produced regions 72to generate a fluid flow restriction 96 therein. As illustrative,non-exclusive examples, foaming agent 92 may block, restrict, and/orocclude fluid flow through produced regions 72, may increase aneffective viscosity of the fluid that is present within produced regions72, and/or may decrease an effective mobility of the fluid that ispresent within produced regions 72, thereby decreasing a flow rate ofpressurizing fluid 82 through produced regions 72.

Foaming agent 92 may restrict fluid flow through produced regions 72 inany suitable manner. As an illustrative, non-exclusive example, thefoaming agent may foam within produced regions 72 to generate fluid flowrestrictions 96. Fluid flow restrictions 96 may be present in anysuitable portion, or fraction, of produced regions 72. As anillustrative, non-exclusive example, and as illustrated in solid linesin FIG. 4, the fluid flow restriction may be present within a fractionof (or less than the entirety of) a volume that is defined by producedregions 72 (or each produced region 72). As another illustrative,non-exclusive example, and as illustrated in dashed lines in FIG. 4, thefluid flow restriction may be present in all (or at least substantiallyall) of the volume that is defined by produced regions 72 (or eachproduced region 72).

Subsequent to formation of fluid flow restrictions 96, and asillustrated in FIG. 5, pressurizing fluid 82 may be pushed, forced,diverted, and/or urged into unproduced regions 76, thereby providing adriving force for flow of reservoir fluid 22 from the unproduced region76. This may decrease the proportion of pressurizing fluid 82 withinproduced fluid 62, increase production of reservoir fluid 22 fromunproduced regions 76, and/or increase an overall sweep efficiency ofsubterranean formation 20 and/or of portion 24 of the subterraneanformation 20.

With reference to FIGS. 1-5, pressurizing fluid 82 may be provided toinjection fracture 50 in any suitable manner. Additionally oralternatively, produced fluid 62 may be received from productionfracture 60 in any suitable manner and/or foaming agent 92 may beprovided to production fracture 60 in any suitable manner.

As an illustrative, non-exclusive example, and as illustrated in solidlines in FIG. 1, hydrocarbon production system 10 may include a wellbore30 that extends within subterranean formation 20, and injection fracture50 and production fracture 60 both may originate and/or emanate fromwellbore 30. Under these conditions, hydrocarbon production system 10further may include an injection conduit 84 that extends within wellbore30 and a production conduit 94 that also extends within wellbore 30 (orwithin the same wellbore 30). Injection conduit 84 may extend and/orprovide fluid communication between pressurizing fluid supply system 80and injection fracture 50. Similarly, production conduit 94 may extendand/or provide fluid communication between foaming agent supply system90 and production fracture 60.

When wellbore 30 includes both injection conduit 84 and productionconduit 94, a portion of the injection conduit that extends within thewellbore may be fluidly isolated from a portion of the productionconduit that extends within the wellbore. As illustrative, non-exclusiveexamples, the injection conduit may be spaced apart from the productionconduit, discrete from the production conduit, fluidly isolated from theproduction conduit, and/or radially spaced apart from the productionconduit.

As more specific but still illustrative, non-exclusive examples,injection conduit 84 and production conduit 94 may be defined byseparate and/or distinct lengths of pipe and/or tubing that extendwithin wellbore 30. As a more specific but still illustrative,non-exclusive example, one of injection conduit 84 and productionconduit 94 may be defined by a length of pipe and/or tubing that extendswithin wellbore 30, while the other may be an annular space that isdefined between the pipe and/or tubing and wellbore 30. Regardless ofthe specific configuration of injection conduit 84 and productionconduit 94, subterranean formation 20 (or portion 24 thereof) mayprovide fluid communication (or indirect fluid communication) betweenthe injection conduit and the production conduit, such as via injectionfracture 50, production fracture 60, and portion 24 of subterraneanformation 20.

As another illustrative, non-exclusive example, hydrocarbon productionsystem 10 may include a production wellbore 32 (as illustrated in solidlines in FIG. 1) and an injection wellbore 34 (as illustrated in dashedlines in FIG. 1). The production wellbore may be spaced apart from,separate from, distinct from, and/or formed separately from theinjection wellbore. Injection conduit 84 may be defined by and/or withininjection wellbore 34, and injection fracture 50 may originate and/oremanate from the injection wellbore. Similarly, production conduit 94may be defined by and/or within production wellbore 32, and productionfracture 60 may originate and/or emanate from the production wellbore.

Under these conditions, pressurizing fluid supply system 80 may beconfigured to provide pressurizing fluid 82 to injection fracture 50 viainjection wellbore 34, and foaming agent supply system 90 may beconfigured to provide foaming agent 92 to production fracture 60 viaproduction wellbore 32. In addition, subterranean formation 20 (orportion 24 thereof) provides fluid communication (or indirect fluidcommunication) between injection wellbore 34 and production wellbore 32via injection fracture 50 and production fracture 60, respectively.

As illustrated in dashed lines in FIG. 1, hydrocarbon production system10 may include a plurality of injection fractures 50 and/or a pluralityof production fractures 60, with each of the injection fractures beingassociated with one or more of the production fractures (or being influid communication therewith via a respective portion of subterraneanformation 20). Thus, and as illustrated in FIG. 1, injection fractures50 and production fractures 60 may alternate along a length ofwellbore(s) 30 (though this alternation is not required).

Each injection fracture may be configured to receive pressurizing fluid82 from pressurizing fluid supply system 80 to provide a driving forcefor flow of reservoir fluid 22 to one or more associated productionfracture(s) 60. Similarly, foaming agent supply system 90 may beconfigured to selectively inject foaming agent 92 into each productionfracture 60, such as to decrease production of pressurizing fluid 82therefrom and/or to increase production of reservoir fluid 22 from thesubterranean formation.

It is within the scope of the present disclosure that hydrocarbonproduction system 10 may define any suitable distance between injectionfractures 50 and associated production fractures 60. As illustrative,non-exclusive examples, the distance may be at least 10 meters (m), atleast 20 m, at least 30 m, at least 40 m, at least 50 m, at least 60 m,at least 70 m, at least 80 m, at least 90 m, or at least 100 m.Additionally or alternatively, the distance also may be less than 400 m,less than 375 m, less than 350 m, less than 325 m, less than 300 m, lessthan 275 m, less than 250 m, less than 225 m, less than 200 m, less than175 m, less than 150 m, or less than 125 m. This distance may beselected based upon any suitable criteria, illustrative, non-exclusiveexamples of which include a fluid permeability of subterranean formation20, a level of heterogeneity of subterranean formation 20, completioncosts, and/or risk of intersection between injection fractures 50 andproduction fractures 60 during formation thereof.

Similarly, it is also within the scope of the present disclosure thatinjection fractures 50 and/or production fractures 60, which maycollectively be referred to herein as fractures 50/60, may extend fromrespective wellbore(s) 30 any suitable distance. As illustrative,non-exclusive examples, fractures 50/60 may extend at least 10 m, atleast 20 m, at least 30 m, at least 40 m, at least 50 m, at least 75 m,at least 100 m, at least 125 m, at least 150 m, at least 175 m, at least200 m, at least 225 m, at least 250 m, at least 300 m, at least 350 m,or at least 400 m from wellbore(s) 30. Additionally or alternatively,fractures 50/60 also may extend less than 600 m, less than 550 m, lessthan 500 m, less than 450 m, less than 400 m, less than 350 m, less than300 m, less than 250 m, less than 200 m, less than 150 m, or less than100 m from wellbore(s) 30.

As illustrated in dashed lines in FIGS. 1-5, fractures 50/60 may includea proppant 70 and also may be referred to herein as propped fractures50/60. Additionally or alternatively, fractures 50/60 may not includeproppant 70 and/or may be referred to herein as unpropped fractures50/60.

Fractures 50/60 may define any suitable orientation, or relativeorientation, with respect to one another and/or with respect towellbore(s) 30 and may be formed along any suitable portion of a lengthof wellbore(s) 30. As an illustrative, non-exclusive example, injectionfracture 50 may be (at least substantially) parallel to productionfracture 60. As another illustrative, non-exclusive example, fractures50/60 may be (at least substantially) planar fractures 50/60. As yetanother illustrative, non-exclusive example, fractures 50/60 may beoriented in (an at least substantially) vertical orientation withinsubterranean formation 20 (i.e., a major axis of fractures 50/60 may bealigned at least substantially along a vertical direction).

As another illustrative, non-exclusive example, and as illustrated inFIG. 1, wellbore(s) 30 may include and/or define (an at leastsubstantially) horizontal portion 36, and fractures 50/60 may emanatefrom the horizontal portion of the wellbore. As yet anotherillustrative, non-exclusive example, wellbores 50/60 may extend (atleast substantially) transverse to wellbore(s) 30 (or to a longitudinalaxis thereof).

As discussed, injection fractures 50 are not in direct fluidcommunication with production fractures 60. Additionally oralternatively, and when a given injection fracture 50 is in direct fluidcommunication with a given production fracture 60, a portion of thegiven injection fracture and/or a portion of the given productionfracture may be plugged, blocked, and/or occluded to prevent directfluid communication therebetween.

Foaming agent supply system 90 may include any suitable structure thatmay be designed, constructed, adapted, and/or configured to providefoaming agent 92 to production fracture 60. As illustrative,non-exclusive examples, foaming agent supply system 90 may include anysuitable tank, pump, compressor, valve, pipe, and/or fluid conduit thatmay be utilized to store the foaming agent, pressurize the foamingagent, regulate a flow rate of the foaming agent, and/or convey thefoaming agent.

Foaming agent 92 may be injected into production fracture 60 at afoaming agent pressure that is sufficient to provide a driving force forflow of the foaming agent into the production fracture and/or into aportion of subterranean formation 20 that is proximal thereto (such asinto produced regions 72 of FIGS. 3-5). As such, foaming agent supplysystem 90 may be configured to provide foaming agent 92 at the foamingagent pressure. This may include foaming agent pressures that aregreater than a hydrostatic pressure within production fracture 60,foaming agent pressures that are greater than a pressure of pressurizingfluid 82 that is provided to injection fracture 50, foaming agentpressures that are greater than a fracture pressure of the subterraneanformation, foaming agent pressures that are (at least substantially)equal to the fracture pressure of the subterranean formation, and/orfoaming agent pressures that are less than the fracture pressure of thesubterranean formation. As illustrative, non-exclusive examples, thefoaming agent pressure may be within a threshold pressure difference ofthe fracture pressure, such as within 25%, within 20%, within 15%,within 10%, or within 5% of the fracture pressure.

Foaming agent supply system 90 may provide the foaming agent toproduction fracture 60 in any suitable manner. As an illustrative,non-exclusive example, the foaming agent supply system may (at leastsubstantially) continuously provide the foaming agent to the productionfracture during a foaming agent injection period. As anotherillustrative, non-exclusive example, the foaming agent supply system mayperiodically and/or intermittently provide the foaming agent to theproduction fracture during the foaming agent injection period. This mayinclude sequentially providing a volume of the foaming agent and avolume of gas to the production fracture.

Foaming agent 92 may be provided to the subterranean formation (and/orfoaming agent supply system 90 may be configured to generate the foamingagent) at any suitable temperature. As illustrative, non-exclusiveexamples, the foaming agent temperature may be less than a subterraneanformation temperature. As more specific but still illustrative,non-exclusive examples, the foaming agent temperature may be at least 5°C., at least 10° C., at least 15° C., at least 20° C., at least 25° C.,at least 30° C., at least 35° C., at least 40° C., at least 45° C., orat least 50° C. less than the subterranean formation temperature.

Foaming agent 92 may be provided to the subterranean formation (and/orfoaming agent supply system 90 may be configured to generate the foamingagent) at any suitable rate, or flow rate. As illustrative,non-exclusive examples, production fracture 60 may define a peakproduction rate when producing produced fluid 62 from subterraneanformation 20, and foaming agent 92 may be provided to the productionfracture at a foaming agent injection rate that is less than the peakproduction rate, (at least substantially) equal to the peak productionrate, or greater than the peak production rate. As more specific butstill illustrative, non-exclusive examples, the foaming agent injectionrate may be within 50%, within 40%, within 30%, within 20%, within 10%,or within 5% of the peak production rate.

Any suitable foaming agent volume of foaming agent 92 may be provided toproduction fracture 60 (and/or foaming agent supply system 90 may beconfigured to provide any suitable volume of the foaming agent to theproduction fracture). As an illustrative, non-exclusive example, portion24 of subterranean formation 20 may define a pore volume, and thefoaming agent volume may be less than the pore volume. As more specificbut still illustrative, non-exclusive examples, the foaming agent volumemay be less than 99%, less than 95%, less than 90%, less than 80%, lessthan 70%, less than 60%, less than 50%, less than 40%, less than 30%,less than 20%, or less than 10% of the pore volume.

Additionally or alternatively, the foaming agent volume also may be atleast a threshold foaming agent volume. As illustrative, non-exclusiveexamples, the foaming agent volume may be at least 0.025 cubic meters,at least 0.05 cubic meters, at least 0.075 cubic meters, at least 0.1cubic meters, at least 0.125 cubic meters, at least 0.15 cubic meters,at least 0.16 cubic meters, at least 0.175 cubic meters, at least 0.2cubic meters, at least 0.25 cubic meters, or at least 0.3 cubic meters.

Foaming agent 92 may include any suitable structure, composition, and/orchemical composition that may permit supply of the foaming agent toproduction fracture 60 and/or that may generate fluid flow restriction96 (as illustrated in FIGS. 4-5) within subterranean formation 20. Asillustrative, non-exclusive examples, foaming agent 92 may includeand/or be a pre-mixed foam, an aqueous solution that includes asurfactant, and/or a water-laden surfactant. Illustrative, non-exclusiveexamples of surfactants that may be utilized with and/or included in thesystems and methods according to the present disclosure include acationic surfactant, an anionic surfactant, a nonionic surfactant, anamphoteric surfactant, an alpha-olefin sulfonated surfactant, a betainesurfactant, a fluorinated surfactant, and a sulfonated ethoxylatedalcohol.

When foaming agent 92 includes the surfactant, it is within the scope ofthe present disclosure that the surfactant may comprise any suitablefraction, or portion, of the foaming agent. As illustrative,non-exclusive examples, the surfactant may comprise at least 0.005weight percent (wt %), at least 0.0075 wt %, at least 0.01 wt %, atleast 0.025 wt %, at least 0.05 wt %, at least 0.075 wt %, at least 0.1wt %, at least 0.2 wt %, or at least 0.3 wt %, at least 0.5 wt %, atleast 0.75 wt %, at least 1 wt %, at least 2 wt %, or at least 3 wt % ofthe foaming agent. Additionally or alternatively, the surfactant alsomay comprise less than 10 wt %, less than 9 wt %, less than 8 wt %, lessthan 7 wt %, less than 6 wt %, less than 5 wt %, less than 4 wt %, lessthan 3 wt %, less than 2 wt %, or less than 1 wt % of the foaming agent.

Pressurizing fluid supply system 80 may include any suitable structurethat may be adapted, configured, designed, and/or constructed to providepressurizing fluid 82 to injection fracture 50. As an illustrative,non-exclusive example, pressurizing fluid supply system 80 may be (atleast substantially) similar to foaming agent supply system 90.

Similar to foaming agent supply system 90, pressurizing fluid supplysystem 80 may be configured to provide pressurizing fluid 82 at apressurizing fluid pressure. The pressurizing fluid pressure may be (atleast substantially) similar to the foaming agent pressure. However, thepressurizing fluid pressure may be less than the foaming agent pressure.As illustrative, non-exclusive examples, the pressurizing fluid pressuremay be less than 95%, less than 90%, less than 85%, less than 80%, lessthan 75%, less than 70%, less than 65%, less than 60%, less than 55%, orless than 50% of the foaming agent pressure.

Pressurizing fluid 82 may include any suitable composition, or chemicalcomposition, that may be utilized with and/or included in the systemsand methods according to the present disclosure. As an illustrative,non-exclusive example, the pressurizing fluid may include and/or be alow density pressurizing fluid. Illustrative, non-exclusive examples oflow density pressurizing fluids include pressurizing fluids with adensity of less than 70%, less than 60%, less than 50%, less than 40%,less than 30%, less than 20%, or less than 10% of a density of water atthe temperature and the pressure that are present within the injectionfracture.

As another illustrative, non-exclusive example, pressurizing fluid 82may include and/or be a low viscosity pressurizing fluid. Illustrative,non-exclusive examples of low viscosity pressurizing fluids includepressurizing fluids with a viscosity that is less than 70%, less than60%, less than 50%, less than 40%, less than 30%, less than 20%, or lessthan 10% of a viscosity of water at the temperature and the pressurethat are present within the injection fracture.

As more specific but still illustrative, non-exclusive examples, thepressurizing fluid may include and/or be a gas and/or a supercriticalfluid. Additional illustrative, non-exclusive examples of pressurizingfluids 82 include carbon dioxide, a light alkane hydrocarbon, methane,sulfur dioxide, nitrogen, water, steam, water vapor, and/or hydrogensulfide.

Pressurizing fluid 82 may define any suitable solubility with, in, orwithin, reservoir fluid 22. As illustrative, non-exclusive examples, thepressurizing fluid may define a finite solubility in the reservoirfluid, may be miscible with the reservoir fluid, and/or may beimmiscible with the reservoir fluid.

Subterranean formation 20 may include any suitable structure thatincludes reservoir fluid 22 and/or that may have fractures 50/60 formedtherein. As an illustrative, non-exclusive example, subterraneanformation 20 may include and/or be a homogeneous, or at leastsubstantially homogeneous, subterranean formation 20 that defines (an atleast substantially) constant fluid permeability throughout a volumethereof. As another illustrative, non-exclusive example, subterraneanformation 20 may include and/or be a heterogeneous, or at leastsubstantially heterogeneous, subterranean formation 20 that defines aplurality of different fluid permeabilities in different regionsthereof. As yet another illustrative, non-exclusive example,subterranean formation 20 may include and/or be a hydrocarbon-containingformation and/or an oil shale formation. Similarly, reservoir fluid 22may include and/or be a hydrocarbon, oil, and/or shale oil.

Subterranean formation 20 may define any suitable fluid permeability, oraverage fluid permeability, prior to formation of fractures 50/60therein. As an illustrative, non-exclusive example, subterraneanformation 20 may be a low permeability subterranean formation wherein atleast a threshold fraction of the volume of the subterranean formationdefines less than a threshold fluid permeability. Illustrative,non-exclusive examples of the threshold fraction of the subterraneanformation include threshold fractions of at least 30%, at least 40%, atleast 50%, at least 60%, at least 70%, at least 80%, or at least 90% ofthe volume of the subterranean formation. Illustrative, non-exclusiveexamples of the threshold fluid permeability include threshold fluidpermeabilities of less than 100 millidarcy (md), less than 75 md, lessthan 50 md, less than 40 md, less than 30 md, less than 20 md, less than10 md, less than 8 md, less than 6 md, less than 4 md, less than 2 md,less than 1 md, less than 0.5 md, less than 0.1 md, greater than 0.01 mdand less than 10 md, or greater than 0.1 md and less than 10 md.

Illustrative, non-exclusive examples of low permeability formationsinclude sandstone, carbonate, or/or shale formations. The permeabilityof a formation may be measured by any suitable method. For example, thepermeability may be measured or determined from core tests or welltests. The average permeability of a formation may be based on athickness-weighted arithmetic average of measured or estimatedpermeabilities within the formation, or it may be based on well testmeasurements. Furthermore, the permeability may vary greatly from regionto region within a given subterranean formation (such as when thesubterranean formation is a heterogeneous subterranean formation), andthere may not be consistency between different measures of permeability.

FIG. 6 is a flowchart depicting methods 100 according to the presentdisclosure. Methods 100 may include forming one or more fractures withina subterranean formation at 110, injecting a pressurizing fluid into aninjection fracture that extends within the subterranean formation at120, and/or producing a produced fluid from a production fracture thatextends within the subterranean formation at 130. Methods 100 furthermay include detecting a variable associated with production of thepressurizing fluid from the production fracture at 140 and/ordetermining that the pressurizing fluid is being produced from theproduction fracture at 150. Methods 100 include injecting a foamingagent into the production fracture at 160, and methods 100 further mayinclude repeating at least a portion of the methods at 170.

Forming one or more fractures within the subterranean formation at 110may include forming the injection fracture and/or the productionfracture in any suitable manner. As illustrative, non-exclusiveexamples, the forming at 110 may include hydraulically, thermally,chemically, and/or mechanically fracturing the subterranean formation togenerate the injection fracture and/or the production fracture.

The forming at 110 further may include restricting and/or avoidingintersection of the injection fracture and the production fracture.Additionally or alternatively, and should the injection fracture and theproduction fracture intersect, the forming at 110 also may includeoccluding a portion of the injection fracture and/or of the productionfracture to restrict direct fluid communication therebetween.

Restricting fluid communication between the injection fracture and theproduction fracture may be accomplished in a variety of manners. Asillustrative, non-exclusive examples, careful selection of the field,well orientation, and/or spacing between the fractures may be utilizedto restrict and/or prevent the intersection. To help carefully selectthe field, well orientation, and/or spacing between the fractures, themethod may include (a) logging the formation while drilling thewellbore, (b) monitoring and analyzing pressures and/or flow rates, (c)well testing after forming the injection fracture and/or the productionfracture, and/or (d) monitoring pressures in adjacent wells.

Logging the formation while drilling the wellbore may include logging toobtain wellbore data and/or analyzing the wellbore data to assist informing the injection fracture and/or the production fracture.Monitoring and analyzing pressures and/or flow rates may includemonitoring and analyzing while forming the injection fracture and/or theproduction fracture. Well testing after forming the injection fractureand/or the production fracture may include well testing to assesseffective fracture lengths. Monitoring pressures in adjacent wells mayinclude monitoring while forming the injection fracture and/or theproduction fracture.

Log data may be used to design fracture spacing to reduce the risk offracture intersection while still maintaining good well performance. Theplanned fracture spacing for the well may be adjusted based on reservoirquality as estimated from porosity and/or resistivity logs. A typicalwell plan often may have a consistent spacing of fractures along thewell, but fracture spacing may be adjusted and/or the planned locationof fractures may be changed if the logs show substantial reservoirquality variations along the length of the wellbore.

Analyzing wellbore and monitoring data may include assessing wherefractures spread, determining an anisotropy in horizontal stresses inthe formation, injection fracture, and/or production fracture, etc.After the wellbore data is analyzed, information such as the stressstate, location of the axis of the wellbore and/or the minimum in-situhorizontal stress may be utilized to mitigate the risk of fractureintersection. As an illustrative, non-exclusive example, the stressstate could be leveraged and the axis of the wellbore could be alignedwith the minimum in-situ horizontal stress to mitigate the risk offracture intersection since fractures tend to open against a minimumin-situ stress and tend to propagate in a directional fashion inreservoirs with strong anisotropy in the horizontal stresses.

Fractures may tend to propagate preferably more to one side of a well(i.e. North) rather than the other direction (i.e. South), which mayneed to be accounted for in the design. Increasing fracture spacing mayreduce the risk of fracture intersection. The design of fracture spacingmay depend on the permeability of the formation, reservoirheterogeneities, completion costs, risk of fracture intersection, andother factors. Identifying whether at least one of the fractures is atleast 50 m long (i.e., the end of the fracture that emanates from thewellbore is at least 50 m from the other end of the fracture where thefracture has two ends) also may reduce the risk of fractureintersection. Fracture half length (i.e. the distance from the furthestend of the fracture and the wellbore) also may affect the risk offracture intersection. Fracture half lengths may range from less than 50m to more than 200 m. Longer fracture half lengths may increase recoverybut also may increase the risk of fracture intersection.

Analyzing the fracture data may include reviewing the data to assesswhether the injection and/or production fractures are havingcommunication challenges and/or to identify what zone (i.e., productionor injection) the fracture is in. After simultaneous injection andproduction begin, early production of water can indicate whetherfractures are intersecting. Production logging tools that measurepressures, temperatures, flow rates, fluid capacitance, fluid density,water-hydrocarbon fractions and/or fluid properties along the wellboremay be used to identify which production fracture(s) in the wellbore maybe communicating with an injection fracture.

Another illustrative, non-exclusive example of a way to identify whichproduction fracture(s) might be in communication with injectionfracture(s) is to monitor data from fixed sensors that have beeninstalled as part of the completion, such as a fiber optic cable used asa distributed temperature sensor. Yet another way of identifying whichproduction fracture(s) might be in communication with injectionfracture(s) is to include different tracers with proppant for eachfracture and analyzing produced fluids for relative tracerconcentrations If one or more of the fractures is having communicationchallenges, workovers may be implemented to plug a problematic injectionzone, and/or a flow control device may be used to prevent injection ofthe fluid into the problematic zone. While some of these ways toidentify are discussed as being alternatives to one another, one or moreof the ways may be implemented.

Injecting the pressurizing fluid into the injection fracture thatextends within the subterranean formation at 120 may include injectingthe pressurizing fluid in any suitable manner to provide a driving forcefor the producing at 130. As an illustrative, non-exclusive example, theinjecting at 120 may include injecting with any suitable pressurizingfluid supply system 80. The injecting at 120 may include (at leastsubstantially) continuously injecting the pressurizing fluid during theproducing at 130, during the detecting at 140, during the determining at150, during the injecting at 160, and/or during the repeating at 170.The injecting at 120 and the injecting at 160 optionally may beperformed at least partially concurrently. Additionally oralternatively, the injecting at 120 also may include intermittentlyinjecting the pressurizing fluid. As an illustrative, non-exclusiveexample, methods 100 further may include ceasing the injecting at 120prior to and/or during at least a portion of the injecting at 160. Underthese conditions, methods 100 also may include ceasing the injecting at160 and resuming the injecting at 120 subsequent to ceasing theinjecting at 160. As another illustrative, non-exclusive example,methods 100 further may include sequentially performing the injecting at120 and the injecting at 160.

The injecting at 120, the producing at 130, and the injecting at 160optionally all may be performed using a single (or the same) wellborethat extends within the subterranean formation. Under these conditions,and as discussed, both the injection fracture and the productionfracture may originate and/or emanate from the single wellbore, and theinjecting at 120 may include injecting via an injection conduit thatextends within the single wellbore and is in fluid communication withthe injection fracture. In addition, the injecting at 160 may includeinjecting via a production conduit that extends within the singlewellbore and is in fluid communication with the production fracture.Additionally or alternatively, the injecting at 120 may be performed viaan injection wellbore that extends within the subterranean formation andis in fluid communication with the injection fracture, while theproducing at 130 and the injecting at 160 may be performed via aproduction wellbore that is spaced apart from, separate from, and/ordistinct from the injection wellbore, extends within the subterraneanformation, and is in fluid communication with the production fracture.

Producing the produced fluid from the production fracture that extendswithin the subterranean formation at 130 may include producing anysuitable produced fluid in any suitable manner. As an illustrative,non-exclusive example, and as discussed, the injecting at 120 mayinclude pressurizing a portion of the subterranean formation to providea driving, or motive, force for the producing at 130. As anotherillustrative, non-exclusive example, the producing at 130 may includeproducing via a production conduit that extends within a single wellborewith an injection conduit that is utilized for the injecting at 120.Additionally or alternatively, the producing at 130 also may includeproducing via a production well that is spaced apart, distinct, and/orseparate from an injection well that is utilized for the injecting at120. As yet another illustrative, non-exclusive example, the producingat 130 may include producing the reservoir fluid, producing thepressurizing fluid, and/or producing a mixture, or combination, of thereservoir fluid and the pressurizing fluid.

Detecting the variable associated with production of the pressurizingfluid from the production fracture at 140 may include detecting anysuitable variable, value, and/or parameter that may be associated withand/or is indicative of the presence of the pressurizing fluid withinthe production fracture and/or production of the pressurizing fluid fromthe production fracture. Illustrative, non-exclusive examples of thevariable associated with production of the pressurizing fluid include(and/or the detecting at 140 may include detecting) a composition (orchemical composition) of the produced fluid, an oil-to-gas ratio and/ora water-to-oil ratio of the produced fluid, and/or a downhole pressurewithin the subterranean formation.

Determining that the pressurizing fluid is being produced from theproduction fracture at 150 may include determining that the pressurizingfluid is being produced in any suitable manner. As an illustrative,non-exclusive example, the determining at 150 may include observing (orvisually observing) the produced fluid to determine that thepressurizing fluid is present within the produced fluid. As anotherillustrative, non-exclusive example, the determining at 150 also mayinclude estimating and/or calculating that the pressurizing fluid is(and/or is likely to be) present within the produced fluid. As yetanother illustrative, non-exclusive example, the determining at 150 maybe at least substantially similar to (and/or may include) the detectingat 140.

Injecting the foaming agent into the production fracture at 160 mayinclude injecting any suitable foaming agent 92 into the productionfracture to limit, slow, reduce, retard, and/or mitigate production ofthe pressurizing fluid 82 from the production fracture. The injecting at160 may be initiated at any suitable time and/or based upon any suitablecriteria. As illustrative, non-exclusive examples, the injecting at 160may be responsive to and/or based, at least in part, on the detecting at140 and/or the determining at 150. As another illustrative,non-exclusive example, the injecting at 160 may include injecting based,at least in part, on a value of the variable associated with productionof the pressurizing fluid from the production fracture.

Methods 100 optionally may include limiting and/or ceasing the producingat 130 during the injecting at 160, such as to permit injection of thefoaming agent into the production fracture. When methods 100 includeceasing the producing at 130 during the injecting at 160, methods 100further may include resuming the producing at 130 subsequent to (orsubsequent to completion of) the injecting at 160. Additionally oralternatively, the producing at 130 may be performed at least partiallyconcurrently with the injecting at 160.

The injecting at 160 may be accomplished in any suitable manner. As anillustrative, non-exclusive example, the injecting at 160 may includeinjecting via the production conduit that extends within the singlewellbore with the injection conduit that is utilized for the injectingat 120. As another illustrative, non-exclusive example, the injecting at160 also may include injecting via the production well that is spacedapart, distinct, and/or separate from the injection well that isutilized for the injecting at 120.

The injecting at 160 may include injecting a continuous, or at leastsubstantially continuous, foaming agent stream. However, it is alsowithin the scope of the present disclosure that the injecting at 160 mayinclude intermittently injecting the foaming agent. As an illustrative,non-exclusive example, the foaming agent may include and/or be a liquidfoaming agent, and the injecting at 160 may include injectingalternating volumes of the liquid foaming agent and of a gas.

The injecting at 160 may include injecting to limit production of thepressurizing fluid from the production fracture. As an illustrative,non-exclusive example, a portion of the subterranean formation that islocated between the injection fracture and the production fracture mayinclude a produced region and an unproduced region. In the producedregion, a substantial portion and/or a majority of the reservoir fluidmay have been removed by flowing to the production fracture. In theunproduced region, a substantial portion and/or a majority of thereservoir fluid may not have been removed. Under these conditions, theinjecting at 160 may include limiting, blocking, and/or occluding flowof the pressurizing fluid through the produced region and/orpreferentially diverting the pressurizing fluid into the unproducedregion. This may improve a sweep efficiency of the portion of thesubterranean formation that is located between the injection fractureand the production fracture.

As an illustrative, non-exclusive example, the injecting at 160 mayinclude increasing a flow resistance within a pore space that ispresent, or defined, within the produced region. As anotherillustrative, non-exclusive example, the injecting at 160 additionallyor alternatively may include increasing an effective viscosity of afluid that is located within the pore space. As discussed herein, theincrease in flow resistance and/or the increase in effective viscositymay be accomplished by generating a foam within the produced region withthe foaming agent.

Repeating at least a portion of the methods at 170 may include repeatingany suitable portion of methods 100 any suitable number of times. Asillustrative, non-exclusive examples, the repeating at 170 may includerepeating the forming at 110, repeating the injecting at 120, repeatingthe producing at 130, repeating that detecting at 140, repeating thedetermining at 150, and/or repeating the injecting at 160. As anotherillustrative, non-exclusive example, the repeating at 170 may includerepeating a plurality of times. This may include repeating at least 2,at least 4, at least 6, at least 8, at least 10, at least 12, at least14, at least 16, at least 18, or at least 20 times.

In the present disclosure, several of the illustrative, non-exclusiveexamples have been discussed and/or presented in the context of flowdiagrams, or flow charts, in which the methods are shown and describedas a series of blocks, or steps. Unless specifically set forth in theaccompanying description, the order of the blocks may vary from theillustrated order in the flow diagram, including with two or more of theblocks (or steps) occurring in a different order and/or concurrently.The blocks, or steps, of the methods optionally may be implemented aslogic, which also may be described as implementing the blocks, or steps,as logics. In some applications, the blocks, or steps, may representexpressions and/or actions to be performed by functionally equivalentcircuits or other logic devices. The illustrated blocks may, but are notrequired to, represent executable instructions that cause a computer,processor, and/or other logic device to respond, to perform an action,to change states, to generate an output or display, and/or to makedecisions.

As used herein, the term “and/or” placed between a first entity and asecond entity means one of (1) the first entity, (2) the second entity,and (3) the first entity and the second entity. Multiple entities listedwith “and/or” should be construed in the same manner, i.e., “one ormore” of the entities so conjoined. Other entities may optionally bepresent other than the entities specifically identified by the “and/or”clause, whether related or unrelated to those entities specificallyidentified. Thus, as a non-limiting example, a reference to “A and/orB,” when used in conjunction with open-ended language such as“comprising” may refer to A only (optionally including entities otherthan B); to B only (optionally including entities other than A); or toboth A and B (optionally including other entities). These entities mayrefer to elements, actions, structures, steps, operations, values, andthe like.

As used herein, the phrase “at least one,” in reference to a list of oneor more entities should be understood to mean at least one entityselected from any one or more of the entity in the list of entities, butnot necessarily including at least one of each and every entityspecifically listed within the list of entities and not excluding anycombinations of entities in the list of entities. This definition alsoallows that entities may optionally be present other than the entitiesspecifically identified within the list of entities to which the phrase“at least one” refers, whether related or unrelated to those entitiesspecifically identified. Thus, as a non-limiting example, “at least oneof A and B” (or, equivalently, “at least one of A or B,” or,equivalently “at least one of A and/or B”) may refer to at least one,optionally including more than one, A, with no B present (and optionallyincluding entities other than B); to at least one, optionally includingmore than one, B, with no A present (and optionally including entitiesother than A); to at least one, optionally including more than one, A,and at least one, optionally including more than one, B (and optionallyincluding other entities). In other words, the phrases “at least one,”“one or more,” and “and/or” are open-ended expressions that are bothconjunctive and disjunctive in operation. For example, each of theexpressions “at least one of A, B and C,” “at least one of A, B, or C,”“one or more of A, B, and C,” “one or more of A, B, or C” and “A, B,and/or C” may mean A alone, B alone, C alone, A and B together, A and Ctogether, B and C together, A, B and C together, and optionally any ofthe above in combination with at least one other entity.

In the event that any patents, patent applications, or other referencesare incorporated by reference herein and (1) define a term in a mannerthat is inconsistent with and/or (2) are otherwise inconsistent with,either the non-incorporated portion of the present disclosure or any ofthe other incorporated references, the non-incorporated portion of thepresent disclosure shall control, and the term or incorporateddisclosure therein shall only control with respect to the reference inwhich the term is defined and/or the incorporated disclosure was presentoriginally.

As used herein the terms “adapted” and “configured” mean that theelement, component, or other subject matter is designed and/or intendedto perform a given function. Thus, the use of the terms “adapted” and“configured” should not be construed to mean that a given element,component, or other subject matter is simply “capable of” performing agiven function but that the element, component, and/or other subjectmatter is specifically selected, created, implemented, utilized,programmed, and/or designed for the purpose of performing the function.It is also within the scope of the present disclosure that elements,components, and/or other recited subject matter that is recited as beingadapted to perform a particular function may additionally oralternatively be described as being configured to perform that function,and vice versa.

Illustrative, non-exclusive examples of systems and methods according tothe present disclosure are presented in the following enumeratedparagraphs. It is within the scope of the present disclosure that anindividual step of a method recited herein, including in the followingenumerated paragraphs, may additionally or alternatively be referred toas a “step for” performing the recited action.

A1. A method of enhancing production of a reservoir fluid from asubterranean formation, the method comprising: injecting a pressurizingfluid into an injection fracture that extends within the subterraneanformation; producing a produced fluid from a production fracture thatextends within the subterranean formation, wherein the productionfracture is spaced apart from the injection fracture and in indirectfluid communication with the injection fracture via a portion of thesubterranean formation that extends therebetween, and further whereinthe injecting provides a driving force for the producing; and injectinga foaming agent into the production fracture to limit production of thepressurizing fluid from the production fracture.

A2. The method of paragraph A1, wherein the method further includesdetecting a variable associated with production of the pressurizingfluid from the production fracture, and further wherein the injecting isbased, at least in part, on the detecting.

A3. The method of any of paragraphs A1-A2, wherein the method furtherincludes determining that the pressurizing fluid is being produced fromthe production fracture, and further wherein the injecting is based, atleast in part, on the determining.

A4. The method of any of paragraphs A1-A3, wherein the injecting thefoaming agent includes injecting the foaming agent based, at least inpart, on a/the variable associated with production of the pressurizingfluid from the production fracture.

A5. The method of any of paragraphs A1-A4, wherein the injecting thefoaming agent includes injecting the foaming agent based, at least inpart, on a composition, or a chemical composition, of the producedfluid.

A6. The method of any of paragraphs A1-A5, wherein the injecting thefoaming agent includes injecting the foaming agent based, at least inpart, on an oil-to-gas ratio and/or a water-to-oil ratio of the producedfluid.

A7. The method of any of paragraphs A1-A6, wherein the injecting thefoaming agent includes injecting the foaming agent based, at least inpart, on a downhole pressure within the subterranean formation.

B1. A method of limiting production of a pressurizing fluid from aproduction fracture that extends within a subterranean formation,wherein the pressurizing fluid is injected into an injection fracturethat is spaced apart from the production fracture, extends within thesubterranean formation, and is in indirect fluid communication with theproduction fracture via a portion of the subterranean formation thatextends therebetween, and further wherein the pressurizing fluid isinjected to provide a driving force for production of a produced fluidfrom the production fracture, the method comprising: detecting avariable associated with production of the pressurizing fluid from theproduction fracture; and injecting a foaming agent into the productionfracture to limit production of the pressurizing fluid from theproduction fracture, wherein the injecting is based, at least in part,on the detecting.

B2. The method of paragraph B1, wherein the method further includesinjecting the pressurizing fluid into the injection fracture.

B3. The method of any of paragraphs B1-B2, wherein the method furtherincludes producing the produced fluid from the production fracture.

C1. The method of any of paragraphs A6-B3, wherein the variableassociated with production of the pressurizing fluid includes a/thecomposition, or a/the chemical composition, of the produced fluid, andoptionally wherein the detecting includes detecting the composition, orthe chemical composition, of the produced fluid.

C2. The method of any of paragraphs A6-C1, wherein the variableassociated with production of the pressurizing fluid includes an/theoil-to-gas ratio of the produced fluid, and optionally wherein thedetecting includes detecting the oil-to-gas ratio of the produced fluid.

C3. The method of any of paragraphs A6-C1, wherein the variableassociated with production of the pressurizing fluid includes a/thewater-to-oil ratio of the produced fluid, and optionally wherein thedetecting includes detecting the water-to-oil ratio of the producedfluid.

C4. The method of any of paragraphs A6-C3, wherein the variableassociated with the production of the pressurizing fluid includes a/thedownhole pressure within the subterranean formation, and optionallywherein the detecting includes detecting the downhole pressure.

C5. The method of any of paragraphs A1-C4, wherein the method furtherincludes ceasing the producing the produced fluid during the injectingthe foaming agent.

C6 The method of paragraph C5, wherein the method includes resuming theproducing the produced fluid subsequent to the injecting the foamingagent.

C7 The method of any of paragraphs A1-C6, wherein the method includesproducing the produced fluid at least partially concurrently withinjecting the pressurizing fluid.

C8. The method of any of paragraphs A1-C7, wherein the injecting thepressurizing fluid includes (at least substantially) continuouslyinjecting the pressurizing fluid during the producing.

C9. The method of any of paragraphs A1-C8, wherein the method furtherincludes continuing the injecting the pressurizing fluid during theinjecting the foaming agent.

C10. The method of any of paragraphs A1-C9, wherein the injecting thepressurizing fluid and the injecting the foaming agent are at leastpartially concurrent.

C11. The method of any of paragraphs A1-C10, wherein the injecting thepressurizing fluid includes intermittently injecting the pressurizingfluid.

C12. The method of any of paragraphs A1-C11, wherein the method furtherincludes ceasing the injecting the pressurizing fluid during theinjecting the foaming agent.

C13. The method of paragraph C12, wherein the method further includesceasing the injecting the foaming agent, and further wherein the methodincludes resuming the injecting the pressurizing fluid subsequent toceasing the injecting the foaming agent.

C14. The method of any of paragraphs A1-C13, wherein the method includessequentially injecting the pressurizing fluid and injecting the foamingagent.

C15. The method of any of paragraphs A1-C14, wherein the method includesinjecting the foaming agent prior to injecting the pressurizing fluid.

C16. The method of any of paragraphs A1-C14, wherein the method includesinjecting the foaming agent after injecting the pressurizing fluid.

C17. The method of any of paragraphs A1-C16, wherein a wellbore extendswithin the subterranean formation, wherein the injection fractureemanates from the wellbore, wherein the production fracture emanatesfrom the wellbore, wherein the injecting the pressurizing fluid includesinjecting the pressurizing fluid via an injection conduit that extendswithin the wellbore and is in fluid communication with the injectionfracture, and further wherein the injecting the foaming agent includesinjecting the foaming agent via a production conduit that extends withinthe wellbore and is in fluid communication with the production fracture.

C18. The method of paragraph C17, wherein the injection conduit is atleast one of spaced apart from the production conduit, discrete from theproduction conduit, fluidly isolated from the production conduit, andradially spaced apart from the production conduit, optionally within thewellbore.

C19. The method of any of paragraphs A1-C16, wherein a productionwellbore extends within the subterranean formation and is in fluidcommunication with the production fracture, wherein an injectionwellbore extends within the subterranean formation and is in fluidcommunication with the injection fracture, wherein the productionwellbore is spaced apart from the injection wellbore, wherein theinjecting the pressurizing fluid includes injecting the pressurizingfluid via the injection wellbore, and further wherein the injecting thefoaming agent includes injecting the foaming agent via the productionwellbore.

C20. The method of any of paragraphs A1-C19, wherein the injecting thefoaming agent includes injecting a continuous, or at least substantiallycontinuous, foaming agent stream.

C21. The method of any of paragraphs A1-C20, wherein the injecting thefoaming agent includes injecting a liquid foaming agent stream.

C22. The method of any of paragraphs A1-C21, wherein the injecting thefoaming agent includes injecting alternating volumes of a/the liquidfoaming agent and a gas.

C23. The method of any of paragraphs A1-C22, wherein the subterraneanformation has a subterranean formation temperature, and further whereinthe injecting the foaming agent includes injecting the foaming agent ata foaming agent temperature that is less than the subterranean formationtemperature, optionally wherein the foaming agent temperature is atleast 5° C., at least 10° C., at least 15° C., at least 20° C., at least25° C., at least 30° C., at least 35° C., at least 40° C., at least 45°C., or at least 50° C. less than the subterranean formation temperature.

C24. The method of any of paragraphs A1-C23, wherein the subterraneanformation defines a fracture pressure, and further wherein the injectingthe foaming agent includes injecting the foaming agent at a foamingagent pressure that is at least one of less than the fracture pressure,(substantially) equal to the fracture pressure, and greater than thefracture pressure, optionally wherein the foaming agent pressure iswithin a threshold pressure difference of the fracture pressure, andfurther optionally wherein the threshold pressure difference is lessthan 25%, less than 20%, less than 15%, less than 10%, or less than 5%of the fracture pressure.

C25. The method of any of paragraphs A1-C24, wherein the productionfracture defines a peak production rate, and further wherein theinjecting the foaming agent includes injecting the foaming agent at afoaming agent injection rate that is at least one of less than the peakproduction rate, (substantially) equal to the peak production rate, andgreater than the peak production rate, optionally wherein the foamingagent injection rate is within a threshold injection rate difference ofthe peak production rate, and further optionally wherein the thresholdinjection rate difference is less than 50%, less than 40%, less than30%, less than 20%, less than 10%, or less than 5% of the peakproduction rate.

C26. The method of any of paragraphs A1-C25, wherein the subterraneanformation defines a pore volume within a portion of the subterraneanformation that is located between the injection fracture and theproduction fracture, and further wherein the injecting the foaming agentincludes injecting a foaming agent volume that is less than the porevolume, optionally wherein the foaming agent volume is less than 99%,less than 95%, less than 90%, less than 80%, less than 70%, less than60%, less than 50%, less than 40%, less than 30%, less than 20%, or lessthan 10% of the pore volume, and further optionally wherein the foamingagent volume is at least 0.025 cubic meters, at least 0.05 cubic meters,at least 0.075 cubic meters, at least 0.1 cubic meters, at least 0.125cubic meters, at least 0.15 cubic meters, at least 0.16 cubic meters, atleast 0.175 cubic meters, at least 0.2 cubic meters, at least 0.25 cubicmeters, or at least 0.3 cubic meters.

C27. The method of any of paragraphs A1-C26, wherein a/the portion ofthe subterranean formation that is located between the injectionfracture and the production fracture includes a produced region, inwhich a majority of the reservoir fluid has been removed by flowing tothe production fracture, and an unproduced region, in which a majorityof the reservoir fluid has not been removed, and further wherein theinjecting the foaming agent includes preferentially diverting thepressurizing fluid into the unproduced region.

C28. The method of paragraph C27, wherein the preferentially divertingincludes increasing a flow resistance within a pore space that ispresent within the produced region.

C29. The method of any of paragraphs C27-C28, wherein the preferentiallydiverting includes increasing an effective viscosity of a fluid that islocated within a/the pore space that is present within the producedregion.

C30. The method of any of paragraphs C27-C29, wherein the preferentiallydiverting includes generating a foam within the produced region with thefoaming agent.

C31. The method of any of paragraphs C27-C30, wherein the preferentiallydiverting includes improving a sweep efficiency of the portion of thesubterranean formation that is located between the injection fractureand the production fracture via the preferentially diverting.

C32. The method of any of paragraphs A1-C31, wherein the method furtherincludes forming at least one, and optionally both, of the injectionfracture and the production fracture.

C33. The method of paragraph C32, wherein the forming includes at leastone of hydraulically, thermally, chemically, and mechanically fracturingthe subterranean formation to generate at least one, and optionallyboth, of the injection fracture and the production fracture.

C34. The method of any of paragraphs C32-C33, wherein the formingincludes restricting intersection of the injection fracture and theproduction fracture.

C35. The method of any of paragraphs C32-C34, wherein the formingincludes selectively occluding a portion of at least one of theinjection fracture and the production fracture to restrict direct fluidcommunication between the injection fracture and the productionfracture.

C36. The method of any of paragraphs C32-C35, wherein the methodincludes forming the production fracture, and further wherein the methodincludes injecting the foaming agent subsequent to forming the producingfracture and prior to injecting the pressurizing fluid.

C37. The method of any of paragraphs A1-C36, wherein the method furtherincludes repeating the method.

C38. The method of paragraph C37, wherein the repeating includes ceasingthe injecting the foaming agent and subsequently initiating theinjecting the foaming agent a plurality of times, optionally wherein theplurality of times includes at least 2, at least 4, at least 6, at least8, at least 10, at least 12, at least 14, at least 16, at least 18, orat least 20 times.

C39. The method of any of paragraphs A1-C38 performed using thehydrocarbon production system of any of paragraphs D1-D21.

D1. A hydrocarbon production system for producing a reservoir fluid froma subterranean formation, the hydrocarbon production system comprising:an injection fracture that extends within the subterranean formation; aproduction fracture that is spaced apart from the injection fracture andextends within the subterranean formation, wherein the productionfracture is in indirect fluid communication with the injection fracturevia a portion of the subterranean formation that extends therebetween; apressurizing fluid supply system that is configured to inject apressurizing fluid into the injection fracture to provide a drivingforce for flow of the reservoir fluid to the production fracture; and afoaming agent supply system that is configured to selectively inject afoaming agent into the production fracture to limit production of thepressurizing fluid from the production fracture.

D2. The hydrocarbon production system of paragraph D1, wherein thehydrocarbon production system includes a wellbore that extends withinthe subterranean formation, wherein the production fracture emanatesfrom the wellbore, and further wherein the injection fracture emanatesfrom the wellbore.

D3 The hydrocarbon production system of paragraph D2, wherein thehydrocarbon production system includes an injection conduit that extendswithin the wellbore between the pressurizing fluid supply system and theinjection fracture, and wherein the hydrocarbon production systemfurther includes a production conduit that extends within the wellborebetween the foaming agent supply system and the production fracture.

D4. The hydrocarbon production system of paragraph D3, wherein a portionof the injection conduit that extends within the wellbore is fluidlyisolated from a portion of the production conduit that extends withinthe wellbore.

D5. The hydrocarbon production system of any of paragraphs D3-D4,wherein the subterranean formation provides fluid communication betweenthe injection conduit and the production conduit via the injectionfracture and the production fracture.

D6. The hydrocarbon production system of any of paragraphs D2-D5,wherein the wellbore includes a horizontal, or at least substantiallyhorizontal, portion, and further wherein the production fracture and theinjection fracture emanate from the horizontal, or at leastsubstantially horizontal, portion.

D7. The hydrocarbon production system of any of paragraphs D2-D6,wherein at least one, and optionally both, of the production fractureand the injection fracture extend (at least substantially) transverse tothe wellbore.

D8 The hydrocarbon production system of paragraph D1, wherein thehydrocarbon production system inludes a production wellbore that extendswithin the subterranean formation and an injection wellbore that extendswithin the subterranean formation and is spaced apart from theproduction wellbore, wherein the production fracture emanates from theproduction wellbore, and further wherein the injection fracture emanatesfrom the injection wellbore.

D9. The hydrocarbon production system of paragraph D8, wherein thepressurizing fluid supply system is configured to provide thepressurizing fluid to the injection fracture via the injection wellbore.

D10. The hydrocarbon production system of any of paragraphs D8-D9,wherein the foaming agent supply system is configured to provide thefoaming agent to the production fracture via the production wellbore.

D11. The hydrocarbon production system of any of paragraphs D8-D10,wherein the subterranean formation provides fluid communication betweenthe injection wellbore and the production wellbore via the injectionfracture and the production fracture.

D12. The hydrocarbon production system of any of paragraphs D8-D11,wherein the injection wellbore includes a horizontal, or at leastsubstantially horizontal, portion, and further wherein the injectionfracture emanates from the horizontal, or at least substantiallyhorizontal, portion of the injection wellbore.

D13. The hydrocarbon production system of any of paragraphs D8-D12,wherein the production wellbore includes a horizontal, or at leastsubstantially horizontal, portion, and further wherein the productionfracture emanates from the horizontal, or at least substantiallyhorizontal, portion of the production wellbore.

D14. The hydrocarbon production system of any of paragraphs D8-D13,wherein the injection fracture extends (at least substantially)transverse to the injection wellbore.

D15. The hydrocarbon production system of any of paragraphs D8-D14,wherein the production fracture extends (at least substantially)transverse to the production wellbore.

D16. The hydrocarbon production system of any of paragraphs D1-D15,wherein the hydrocarbon production system includes a plurality ofproduction fractures and a plurality of injection fractures that areassociated therewith.

D17. The hydrocarbon production system of paragraph D16, wherein each ofthe plurality of injection fractures is configured to receive thepressurizing fluid from the pressurizing fluid supply system to providea driving force for flow of the reservoir fluid to at least one of theplurality of production fractures.

D18. The hydrocarbon production system of any of paragraphs D16-D17,wherein the foaming agent supply system is configured to selectivelyinject the foaming agent into each of the plurality of productionfractures.

D19. The hydrocarbon production system of any of paragraphs D1-D18,wherein the hydrocarbon production system further includes thepressurizing fluid.

D20. The hydrocarbon production system of any of paragraphs D1-D19,wherein the hydrocarbon production system further includes the foamingagent.

D21. The hydrocarbon production system of any of paragraphs D1-D20,wherein the foaming agent supply system is configured to sequentiallysupply a volume of the foaming agent and a volume of gas to theproduction fracture.

E1. The method of any of paragraphs A1-C39 or the hydrocarbon productionsystem of any of paragraphs D1-D21, wherein the production fracture is(at least substantially) parallel to the injection fracture.

E2. The method of any of paragraphs A1-C39 or E1 or the hydrocarbonproduction system of any of paragraphs D1-D21, wherein at least one, andoptionally both, of the production fracture and the injection fractureincludes a proppant.

E3. The method of any of paragraphs A1-C39 or E1-E2 or the hydrocarbonproduction system of any of paragraphs D1-D21, wherein at least one, andoptionally both, of the production fracture and the injection fracturedoes not include a proppant.

E4. The method of any of paragraphs A1-C39 or E1-E3 or the hydrocarbonproduction system of any of paragraphs D1-D21, wherein at least one, andoptionally both, of the production fracture and the injection fractureis a planar, or at least substantially planar, fracture.

E5. The method of any of paragraphs A1-C39 or E1-E4 or the hydrocarbonproduction system of any of paragraphs D1-D21, wherein at least one, andoptionally both, of the production fracture and the injection fractureis a vertically oriented, or at least substantially vertically oriented,fracture.

E6. The method of any of paragraphs A1-C39 or E1-E5 or the hydrocarbonproduction system of any of paragraphs D1-D21, wherein the pressurizingfluid is a low density pressurizing fluid, optionally wherein thepressurizing fluid defines a density of less than 70%, less than 60%,less than 50%, less than 40%, less than 30%, less than 20%, or less than10% of a density of water at the temperature and the pressure that aredefined within the injection fracture.

E7. The method of any of paragraphs A1-C39 or E1-E6 or the hydrocarbonproduction system of any of paragraphs D1-D21, wherein the pressurizingfluid is a low viscosity pressurizing fluid, optionally wherein thepressurizing fluid defines a viscosity of less than 70%, less than 60%,less than 50%, less than 40%, less than 30%, less than 20%, or less than10% of a viscosity of water at the temperature and the pressure that aredefined within the injection fracture.

E8. The method of any of paragraphs A1-C39 or E1-E7 or the hydrocarbonproduction system of any of paragraphs D1-D21, wherein the pressurizingfluid includes, and optionally is, at least one, and optionally both, ofa gas and a supercritical fluid.

E9. The method of any of paragraphs A1-C39 or E1-E8 or the hydrocarbonproduction system of any of paragraphs D1-D21, wherein the pressurizingfluid at least one of defines a finite solubility in the reservoirfluid, is miscible with the reservoir fluid, and is immiscible with thereservoir fluid.

E10. The method of any of paragraphs A1-C39 or E1-E9 or the hydrocarbonproduction system of any of paragraphs D1-D21, wherein the pressurizingfluid includes, and optionally is, at least one, optionally at leasttwo, and further optionally at least three, of carbon dioxide, a lightalkane hydrocarbon, methane, sulfur dioxide, nitrogen, water, steam,water vapor, and hydrogen sulfide.

E11. The method of any of paragraphs A1-C39 or E1-E9 or the hydrocarbonproduction system of any of paragraphs D1-D21, wherein the pressurizingfluid includes, wholly or in part, water.

E12. The method of any of paragraphs A1-C39 or E1-E11 or the hydrocarbonproduction system of any of paragraphs D1-D21, wherein the foaming agentis located within the production fracture.

E13. The method of any of paragraphs A1-C39 or E1-E12 or the hydrocarbonproduction system of any of paragraphs D1-D21, wherein the foaming agentincludes at least one of a pre-mixed foam, an aqueous solution thatincludes a surfactant, and a water-laden surfactant.

E14. The method of paragraph E13 or the hydrocarbon production system ofany of paragraphs D1-D21, wherein the surfactant includes at least oneof a cationic surfactant, an anionic surfactant, a nonionic surfactant,an amphoteric surfactant, an alpha-olefin sulfonated surfactant, abetaine surfactant, a fluorinated surfactant, and a sulfonatedethoxylated alcohol.

E15. The method of any of paragraphs E13-E14 or the hydrocarbonproduction system of any of paragraphs D1-D21, wherein the surfactantdefines a concentration within the foaming agent of at least one of: atleast 0.005 wt %, at least 0.0075 wt %, at least 0.01 wt %, at least0.025 wt %, at least 0.05 wt %, at least 0.075 wt %, at least 0.1 wt %,at least 0.2 wt %, at least 0.3 wt %, at least 0.5 wt %, at least 0.75wt %, at least 1 wt %, at least 2 wt %, or at least 3 wt %; and lessthan 10 wt %, less than 9 wt %, less than 8 wt %, less than 7 wt %, lessthan 6 wt %, less than 5 wt %, less than 4 wt %, less than 3 wt %, lessthan 2 wt %, or less than 1 wt %.

E16. The method of any of paragraphs A1-C39 or E1-E15 or the hydrocarbonproduction system of any of paragraphs D1-D21, wherein the subterraneanformation is a homogeneous, or at least substantially homogeneous,subterranean formation.

E17. The method of any of paragraphs A1-C39 or E1-E15 or the hydrocarbonproduction system of any of paragraphs D1-D21, wherein the subterraneanformation is a heterogeneous, or at least substantially heterogeneous,subterranean formation.

E18. The method of any of paragraphs A1-C39 or E1-E17 or the hydrocarbonproduction system of any of paragraphs D1-D21, wherein the subterraneanformation is a low permeability subterranean formation, optionallywherein at least a threshold fraction of a volume of the subterraneanformation defines less than a threshold fluid permeability.

E19. The method of paragraph E18 or the hydrocarbon production system ofany of paragraphs D1-D21, wherein the threshold fraction of thesubterranean formation is at least 30%, at least 40%, at least 50%, atleast 60%, at least 70%, at least 80%, or at least 90% of the volume ofthe subterranean formation.

E20. The method of any of paragraphs E18-E19 or the hydrocarbonproduction system of any of paragraphs D1-D21, wherein the thresholdfluid permeability is less than 100 millidarcy (md), less than 75 md,less than 50 md, less than 40 md, less than 30 md, less than 20 md, lessthan 10 md, less than 8 md, less than 6 md, less than 4 md, less than 2md, less than 1 md, less than 0.5 md, or less than 0.1 md.

E21. The method of any of paragraphs E18-E20 or the hydrocarbonproduction system of any of paragraphs D1-D21, wherein the thresholdfluid permeability is greater than 0.01 millidarcy (md) and less than 10md, optionally greater than 0.1 md and less than 10 md.

F1. The use of any of the methods of any of paragraphs A1-C39 or E1-E21with any of the hydrocarbon production systems of any of paragraphsD1-D21.

F2. The use of any of the hydrocarbon production systems of any ofparagraphs D1-E20 with any of the methods of any of paragraphs A1-C39 orE1-E21.

F3. The use of any of the methods of any of paragraphs A1-C39 or E1-E21or any of the hydrocarbon production systems of any of paragraphs D1-D21to limit production of a pressurizing fluid from a subterraneanformation.

F4. The use of any of the methods of any of paragraphs A1-C39 or E1-E21or any of the hydrocarbon production systems of any of paragraphs D1-D21to improve sweep of a subterranean formation.

F5. The use of any of the methods of any of paragraphs A1-C39 or E1-E21or any of the hydrocarbon production systems of any of paragraphs D1-D21to enhance production of a reservoir fluid from a subterraneanformation.

F6. The use of a foaming agent to limit production of a pressurizingfluid from a fractured subterranean formation.

EP1. A method of enhancing production of a reservoir fluid from asubterranean formation, the method comprising: injecting a pressurizingfluid into an injection fracture that extends within the subterraneanformation; producing a produced fluid from a production fracture thatextends within the subterranean formation, wherein the productionfracture is spaced apart from the injection fracture and in indirectfluid communication with the injection fracture via a portion of thesubterranean formation that extends therebetween, and further whereinthe injecting provides a driving force for the producing; and injectinga foaming agent into the production fracture to limit production of thepressurizing fluid from the production fracture.

EP2. The method of paragraph EP1, wherein the method further includesceasing the producing the produced fluid during the injecting thefoaming agent, and further wherein the method includes resuming theproducing the produced fluid subsequent to the injecting the foamingagent.

EP3. The method of any of paragraphs EP1 or EP2, wherein a wellboreextends within the subterranean formation, wherein the injectionfracture emanates from the wellbore, wherein the production fractureemanates from the wellbore, wherein the injecting the pressurizing fluidincludes injecting the pressurizing fluid via an injection conduit thatextends within the wellbore and is in fluid communication with theinjection fracture, and wherein the injecting the foaming agent includesinjecting the foaming agent via a production conduit that extends withinthe wellbore and is in fluid communication with the production fracture,and further wherein the injection conduit is at least one of spacedapart from the production conduit, discrete from the production conduit,fluidly isolated from the production conduit, and radially spaced apartfrom the production conduit within the wellbore.

EP4. The method of any of paragraphs EP1 or EP2, wherein a productionwellbore extends within the subterranean formation and is in fluidcommunication with the production fracture, wherein an injectionwellbore extends within the subterranean formation and is in fluidcommunication with the injection fracture, wherein the productionwellbore is spaced apart from the injection wellbore, wherein theinjecting the pressurizing fluid includes injecting the pressurizingfluid via the injection wellbore, and further wherein the injecting thefoaming agent includes injecting the foaming agent via the productionwellbore.

EP5. The method of any of paragraphs EP1-EP4, wherein a portion of thesubterranean formation that is located between the injection fractureand the production fracture includes a produced region, in which amajority of the reservoir fluid has been removed by flowing to theproduction fracture, and an unproduced region, in which a majority ofthe reservoir fluid has not been removed, and further wherein theinjecting the foaming agent includes preferentially diverting thepressurizing fluid into the unproduced region, and optionally whereinthe preferentially diverting includes at least one of increasing a flowresistance within a pore space that is present within the producedregion and increasing an effective viscosity of a fluid that is locatedwithin the pore space.

EP6. The method of any of paragraphs EP1-EP5, wherein the method furtherincludes forming at least one of the injection fracture and theproduction fracture, and optionally wherein the forming includesrestricting intersection of the injection fracture and the productionfracture.

EP7. The method of any of paragraphs EP1-EP6, wherein the method furtherincludes detecting a variable associated with production of thepressurizing fluid from the production fracture, and further wherein theinjecting is based, at least in part, on the detecting.

EP8. The method of any of paragraphs EP1-EP7, wherein the method furtherincludes determining that the pressurizing fluid is being produced fromthe production fracture, and further wherein the injecting is based, atleast in part, on the determining.

EP9. The method of any of paragraphs EP1-EP8, wherein the injecting thefoaming agent includes injecting the foaming agent based, at least inpart, on at least one of a composition of the produced fluid, anoil-to-gas ratio and/or a water-to-oil ratio of the produced fluid, anda downhole pressure within the subterranean formation.

EP10. A method of limiting production of a pressurizing fluid from aproduction fracture within a subterranean formation, wherein thepressurizing fluid is injected into an injection fracture that is spacedapart from the production fracture, extends within the subterraneanformation, and is in indirect fluid communication with the productionfracture via a portion of the subterranean formation that extendstherebetween, and further wherein the pressurizing fluid is injected toprovide a driving force for production of a produced fluid from theproduction fracture, the method comprising: detecting a variableassociated with production of the pressurizing fluid from the productionfracture; and injecting a foaming agent into the production fracture tolimit production of the pressurizing fluid from the production fracture,wherein the injecting is based, at least in part, on the detecting.

EP11. A hydrocarbon production system for producing a reservoir fluidfrom a subterranean formation, the hydrocarbon production systemcomprising: an injection fracture that extends within the subterraneanformation; a production fracture that is spaced apart from the injectionfracture and extends within the subterranean formation, wherein theproduction fracture is in indirect fluid communication with theinjection fracture via a portion of the subterranean formation thatextends therebetween; a pressurizing fluid supply system that isconfigured to inject a pressurizing fluid into the injection fracture toprovide a driving force for flow of the reservoir fluid to theproduction fracture; and a foaming agent supply system that isconfigured to selectively inject a foaming agent into the productionfracture to limit production of the pressurizing fluid from theproduction fracture.

EP12. The hydrocarbon production system of paragraph EP11, wherein thehydrocarbon production system includes a wellbore that extends withinthe subterranean formation, wherein the production fracture emanatesfrom the wellbore, and further wherein the injection fracture emanatesfrom the wellbore.

EP13 The hydrocarbon production system of paragraph EP12, wherein thehydrocarbon production system includes an injection conduit that extendswithin the wellbore between the pressurizing fluid supply system and theinjection fracture, and wherein the hydrocarbon production systemfurther includes a production conduit that extends within the wellborebetween the foaming agent supply system and the production fracture, andoptionally wherein a portion of the injection conduit that extendswithin the wellbore is fluidly isolated from a portion of the productionconduit that extends within the wellbore.

EP14. The hydrocarbon production system of paragraph EP11, wherein thehydrocarbon production system includes a production wellbore thatextends within the subterranean formation and an injection wellbore thatextends within the subterranean formation and is spaced apart from theproduction wellbore, wherein the production fracture emanates from theproduction wellbore, and further wherein the injection fracture emanatesfrom the injection wellbore, and optionally wherein the pressurizingfluid supply system is configured to provide the pressurizing fluid tothe injection fracture via the injection wellbore, and furtheroptionally wherein the foaming agent supply system is configured toprovide the foaming agent to the production fracture via the productionwellbore.

EP15. The hydrocarbon production system of any of paragraphs EP11-EP14,wherein the hydrocarbon production system includes a plurality ofproduction fractures and a plurality of injection fractures that areassociated therewith, wherein each of the plurality of injectionfractures is configured to receive the pressurizing fluid from thepressurizing fluid supply system to provide a driving force for flow ofthe reservoir fluid to at least one of the plurality of productionfractures, and further wherein the foaming agent supply system isconfigured to selectively inject the foaming agent into each of theplurality of production fractures.

1. A method of enhancing production of a reservoir fluid from asubterranean formation, the method comprising: injecting a pressurizingfluid into an injection fracture that extends within the subterraneanformation; producing a produced fluid from a production fracture thatextends within the subterranean formation, wherein the productionfracture is spaced apart from the injection fracture and in indirectfluid communication with the injection fracture via a portion of thesubterranean formation that extends therebetween, and further whereinthe injecting provides a driving force for the producing; and injectinga foaming agent into the production fracture to limit production of thepressurizing fluid from the production fracture.
 2. The method of claim1, wherein the method further includes ceasing the producing theproduced fluid during the injecting the foaming agent, and furtherwherein the method includes resuming the producing the produced fluidsubsequent to the injecting the foaming agent.
 3. The method of claim 1,wherein the injecting the pressurizing fluid and the injecting thefoaming agent are at least partially concurrent.
 4. The method of claim1, wherein the method includes sequentially injecting the pressurizingfluid and injecting the foaming agent.
 5. The method of claim 1, whereina wellbore extends within the subterranean formation, wherein theinjection fracture emanates from the wellbore, wherein the productionfracture emanates from the wellbore, wherein the injecting thepressurizing fluid includes injecting the pressurizing fluid via aninjection conduit that extends within the wellbore and is in fluidcommunication with the injection fracture, and wherein the injecting thefoaming agent includes injecting the foaming agent via a productionconduit that extends within the wellbore and is in fluid communicationwith the production fracture, and further wherein the injection conduitis at least one of spaced apart from the production conduit, discretefrom the production conduit, fluidly isolated from the productionconduit, and radially spaced apart from the production conduit withinthe wellbore.
 6. The method of claim 1, wherein a production wellboreextends within the subterranean formation and is in fluid communicationwith the production fracture, wherein an injection wellbore extendswithin the subterranean formation and is in fluid communication with theinjection fracture, wherein the production wellbore is spaced apart fromthe injection wellbore, wherein the injecting the pressurizing fluidincludes injecting the pressurizing fluid via the injection wellbore,and further wherein the injecting the foaming agent includes injectingthe foaming agent via the production wellbore.
 7. The method of claim 1,wherein the injecting the foaming agent includes injecting an at leastsubstantially continuous foaming agent stream.
 8. The method of claim 1,wherein the injecting the foaming agent includes injecting alternatingvolumes of a liquid foaming agent and a gas.
 9. The method of claim 1,wherein a portion of the subterranean formation that is located betweenthe injection fracture and the production fracture includes a producedregion, in which a majority of the reservoir fluid has been removed byflowing to the production fracture, and an unproduced region, in which amajority of the reservoir fluid has not been removed, and furtherwherein the injecting the foaming agent includes preferentiallydiverting the pressurizing fluid into the unproduced region.
 10. Themethod of claim 9, wherein the preferentially diverting includes atleast one of increasing a flow resistance within a pore space that ispresent within the produced region and increasing an effective viscosityof a fluid that is located within the pore space.
 11. The method ofclaim 9, wherein the preferentially diverting includes generating a foamwithin the produced region with the foaming agent.
 12. The method ofclaim 1, wherein the method further includes forming at least one of theinjection fracture and the production fracture.
 13. The method of claim12, wherein the forming includes restricting intersection of theinjection fracture and the production fracture.
 14. The method of claim1, wherein the method further includes repeating the method, wherein therepeating includes ceasing the injecting the foaming agent andsubsequently initiating the injecting the foaming agent at least sixtimes.
 15. The method of claim 1, wherein the method further includesdetecting a variable associated with production of the pressurizingfluid from the production fracture, and further wherein the injecting isbased, at least in part, on the detecting.
 16. The method of claim 1,wherein the method further includes determining that the pressurizingfluid is being produced from the production fracture, and furtherwherein the injecting is based, at least in part, on the determining.17. The method of claim 1, wherein the injecting the foaming agentincludes injecting the foaming agent based, at least in part, on atleast one of a composition of the produced fluid, an oil-to-gas ratio ofthe produced fluid, and a downhole pressure within the subterraneanformation.
 18. The method of claim 1, wherein the injecting the foamingagent includes injecting the foaming agent based, at least in part, onat least one of a composition of the produced fluid, a water-to-oilratio of the produced fluid, and a downhole pressure within thesubterranean formation.
 19. A method of limiting production of apressurizing fluid from a production fracture within a subterraneanformation, wherein the pressurizing fluid is injected into an injectionfracture that is spaced apart from the production fracture, extendswithin the subterranean formation, and is in indirect fluidcommunication with the production fracture via a portion of thesubterranean formation that extends therebetween, and further whereinthe pressurizing fluid is injected to provide a driving force forproduction of a produced fluid from the production fracture, the methodcomprising: detecting a variable associated with production of thepressurizing fluid from the production fracture; and injecting a foamingagent into the production fracture to limit production of thepressurizing fluid from the production fracture, wherein the injectingis based, at least in part, on the detecting.
 20. A hydrocarbonproduction system for producing a reservoir fluid from a subterraneanformation, the hydrocarbon production system comprising: an injectionfracture that extends within the subterranean formation; a productionfracture that is spaced apart from the injection fracture and extendswithin the subterranean formation, wherein the production fracture is inindirect fluid communication with the injection fracture via a portionof the subterranean formation that extends therebetween; a pressurizingfluid supply system that is configured to inject a pressurizing fluidinto the injection fracture to provide a driving force for flow of thereservoir fluid to the production fracture; and a foaming agent supplysystem that is configured to selectively inject a foaming agent into theproduction fracture to limit production of the pressurizing fluid fromthe production fracture.
 21. The hydrocarbon production system of claim20, wherein the hydrocarbon production system includes a wellbore thatextends within the subterranean formation, wherein the productionfracture emanates from the wellbore, and further wherein the injectionfracture emanates from the wellbore.
 22. The hydrocarbon productionsystem of claim 21, wherein the hydrocarbon production system includesan injection conduit that extends within the wellbore between thepressurizing fluid supply system and the injection fracture, and whereinthe hydrocarbon production system further includes a production conduitthat extends within the wellbore between the foaming agent supply systemand the production fracture.
 23. The hydrocarbon production system ofclaim 22, wherein a portion of the injection conduit that extends withinthe wellbore is fluidly isolated from a portion of the productionconduit that extends within the wellbore.
 24. The hydrocarbon productionsystem of claim 20, wherein the hydrocarbon production system includes aproduction wellbore that extends within the subterranean formation andan injection wellbore that extends within the subterranean formation andis spaced apart from the production wellbore, wherein the productionfracture emanates from the production wellbore, and further wherein theinjection fracture emanates from the injection wellbore.
 25. Thehydrocarbon production system of claim 24, wherein the pressurizingfluid supply system is configured to provide the pressurizing fluid tothe injection fracture via the injection wellbore, and further whereinthe foaming agent supply system is configured to provide the foamingagent to the production fracture via the production wellbore.
 26. Thehydrocarbon production system of claim 20, wherein the hydrocarbonproduction system includes a plurality of production fractures and aplurality of injection fractures that are associated therewith, whereineach of the plurality of injection fractures is configured to receivethe pressurizing fluid from the pressurizing fluid supply system toprovide a driving force for flow of the reservoir fluid to at least oneof the plurality of production fractures, and further wherein thefoaming agent supply system is configured to selectively inject thefoaming agent into each of the plurality of production fractures. 27.The hydrocarbon production system of claim 20, wherein the hydrocarbonproduction system further includes the pressurizing fluid and thefoaming agent.
 28. The hydrocarbon production system of claim 27,wherein the pressurizing fluid is a low density pressurizing fluid thatdefines a density of less than 70% of a density of water at thetemperature and the pressure that are defined within the injectionfracture, and further wherein the pressurizing fluid is a low viscositypressurizing fluid that defines a viscosity of less than 70% of aviscosity of water at the temperature and the pressure that are definedwithin the injection fracture.
 29. The hydrocarbon production system ofclaim 27, wherein the pressurizing fluid includes at least one of a gasand a supercritical fluid.
 30. The hydrocarbon production system ofclaim 27, wherein the foaming agent includes at least one of a pre-mixedfoam, an aqueous solution that includes a surfactant, and a water-ladensurfactant.
 31. The hydrocarbon production system of claim 20, whereinthe subterranean formation is a low permeability subterranean formation,wherein at least a threshold fraction of a volume of the subterraneanformation defines less than a threshold fluid permeability.
 32. Thehydrocarbon production system of claim 31, wherein the thresholdfraction of the subterranean formation is at least 50% of the volume ofthe subterranean formation, and further wherein the threshold fluidpermeability is less than 10 md.